Heavy crude oil deposits commonly known as oil sands, have been found, among other places, in the Athabasca, Peace River, and Cold Lake regions in Alberta, Canada, the Jobo or Orinocco Belt regions in Venezuela, and the Edna and Sisquoc regions of California. The bitumen contained in the oil sands is highly viscous and immobile at ordinary reservoir temperatures. Higher temperatures can liquefy the bitumen and encourage its recovery from the oil sands.
Various methods have been used to extract bitumen from oil sands, but they commonly involve using steam to heat the formation, liquefy the bitumen, and move it to a production well. Steam-based thermal recovery methods include steam flooding (or steam drive), cyclic steam stimulation (“CSS,” also known as “huff and puff”), and steam-assisted gravity drainage (hereinafter also called “SAGD”).
In the steam drive process, steam is injected into a vertical injection well. A series of production wells usually surrounds the injection site. Steam is injected under conditions effective to liquefy the bitumen and drive it toward the production wells. It is known to introduce surfactant compositions into the injection wells in a steam drive process to increase the viscosity of the steam and use it more efficiently to recover the heavy oil.
Cyclic steam stimulation involves a single well and cycles of steam injection for days or weeks (the “huff” part), a soak period to allow the steam to soften the formation over several days, and oil recovery (the “puff” part) for weeks or months. Surfactant solutions and steam foams have been used in conjunction with CSS processes.
Steam-assisted gravity drainage has been known since the early 1980s (see U.S. Pat. No. 4,344,485 and Can. Pat. No. 1,304,287). In the SAGD process, closely spaced horizontal well pairs are drilled into the tar sands. Steam is injected, usually through a tube or “stringer,” into the upper (“injection”) well. As the steam emerges from the stringer, it rises, heats the tar sands formation, softens the bitumen, and creates a widening steam chamber above the steam injection site. Heated oil and condensate flow by gravity and are drained continuously from the lower (“production”) well. During start-up, there is a pressure difference between the injection and production wells, and this pressure difference helps to drive oil production. However, steam eventually breaks through to the production well and eliminates this pressure difference, and production becomes dominated by gravity flow rather than the combined effects of pressure and gravity.
Variations on the SAGD concept have been taught, although most of these involve drilling of additional wells (see, e.g., U.S. Pat. Nos. 7,556,099 and 6,257,334), strategic use of heat (e.g, U.S. Pat. Nos. 7,934,549 and 8,607,866), or introduction of solvents (e.g., U.S. Pat. No. 8,258,639) to improve results.
One simulation indicates that steam foam may be of value in SAGD for improving efficiency in utilization of steam (see Q. Chen et al., SPE 129847 (2010), “Improving Steam-Assisted Gravity Drainage Using Mobility Control Foams: Foam Assisted-SAGD (FA-SAGD)”).
The authors conclude that steam foam could improve results with SAGD by achieving more uniform formation of steam chambers along the full length of the injector well and by improving control over steam breakthrough by sustaining a liquid level between the injector and producer wells.
In a recent paper (SPE 170129-MS, “Design of Thermally Stable Surfactants Formulations for Steam Foam Injection,” 2014), Cuenca et al. suggest that steam foams from traditional anionic surfactants such as alpha-olefin sulfonates (AOS) and alkyl aryl sulfonates (AAS) can be used for steam injection processes performed under anaerobic conditions at relatively high temperatures (up to 240° C.), particularly when used in conjunction with certain “foam boosters.” The authors do not describe the foam booster compositions.
Steam foams have been suggested for use in the early stages of a SAGD process. For example, U.S. Pat. No. 5,215,146 teaches to reduce the start-up time of a SAGD process by injecting foam into an injection well following steam breakthrough. According to the '146 patent, foam entry into the inter-well region helps to maintain a pressure difference between the injection and production wells, thereby increasing production at start-up. Similarly, PCT Internat. Appl. No.
WO 2010/084369 teaches to inject a particulate-containing foam into an injection well. As steam breakthrough to the production well begins to occur, foam and particles plug the gap and help to improve control of steam propagation and development of the steam chamber.
Given that steam breakthrough between the injection and production wells will occur early in a SAGD well pair's useful lifetime, a need remains for ways to utilize steam more efficiently that are not limited to the start-up phase.
So far, surfactants have not been utilized much in SAGD processes, in part because high-quality steam (typically 80+% steam) is injected. Because relatively little liquid is being introduced into a steam stringer, only a limited amount of a surfactant can be introduced this way. To aggravate the problem, steam moves upward rapidly from slots in the upper portion of the horizontal steam pipe and into the steam chamber, while any liquids introduced will flow through bottom slots and in the direction of the production well. It is thus a challenge to introduce a surfactant solution along with steam in a SAGD process while avoiding early phase separation of the steam from the surfactant solution.
In sum, methods for improving steam utilization in a SAGD process are needed. Ideally, the methods could be helpful even after steam breakthrough from the injection well to the production well has already occurred and the well is operating under a gravity-dominated regime. Of interest are particular ways to utilize steam foam in a SAGD system such that escape of steam from the steam chamber can be minimized.